PREPARED BY
William R. Berry II
DIGITAL PETROPHYSICS, INC.
Geologist/Petrophysicist
Deborah M. Olson
Geologist/Petrophysicist
David J. Crane
Geologist/Petrophysicist
UNDER SUBCONTRACT TO
DOE CONTRACT NO. DE-AC22-94BC14892
MICHIGAN TECHNOLOGICAL UNIVERSITY
1.0 SUMMARY
This study was performed under subcontract to Michigan Technological University as part of a grant from the Department of Energy to demonstrate computer analysis and visualization techniques for a reservoir description project. The Pioneer Field area, located approximately 10 miles southeast of the town of Maricopa in the San Joaquin Valley, California, was chosen for the example study. This area is located on the plunging nose of an anticline and therefore has considerable structural relief. The project focused on the upper Miocene siliceous shales, but the overlying shaly sands of the Etchegoin Formation were also included in the geological and petrophysical analysis.
The study area was good for demonstration purposes for a variety of reasons. The shaly sand and siliceous reservoirs are typical of the more challenging lithologies present in California, and that are most difficult to characterize and visualize for operators now facing redevelopment or EOR activities to maintain production. The combination of new wells and old E-logs present at Pioneer is quite typical of California's oil fields, and part of the results of this study is a technique for using these data as part of a reservoir evaluation. The area is located on an anticline with high relief and major faults, which is often difficult to visualize from 2-D paper cross sections and maps, so 3-D visualization techniques are quite applicable here.
The diatomaceous reservoirs of the Monterey Formation consist predominantly of siliceous, cherty shales containing various amounts of clay and silt. These reservoirs have high porosities and low permeabilities. The key to production in the Opal-Ct and quartz phases is brittleness and fracture permeability. Most of the siliceous section at Pioneer is in the Opal-Ct to quartz phase, which is at a higher diagenetic grade than its current depth would allow. This indicates that the Miocene was at one time buried deeper than it is now.
The petrophysical and geological analysis that has been performed as part of this study, and that is discussed in this report, resulted in a reservoir description including lithology and porosity for all wells, and water saturation for those wells with adequate logs. Additionally, a methodology is presented for using the wells with porosity logs to calibrate an empirical model for deriving lithology and porosity from the E-log only wells.
2.0 INTRODUCTION
The main objective of the project is to provide
the smaller oil field operator with the approach and technology
required to undertake an E.O.R. reservoir characterization and
evaluation similar to those performed by larger international
companies.
The scope of work outlined in the project proposal
is categorized into several interactive and parallel phases.
. Database Initialization and Management
. Log Calibration and Analyses
. Rock Measurement
. Petrophysical and Geological Modelling
The database management phase provided the
vehicle for integrating all available data and interpreted results
into the project to enable the process of visualization. This
phase involved numerous related tasks including data gathering,
digitizing, and construction of an interactive multi-media database.
This phase of the project was ongoing and interactive throughout
the entire study.
The log calibration and analyses phase involved
a detailed review of all of the available log and other well
data, and capturing these data digitally for use in the various
parts of the project.
The rock measurement work involved the use
of various standard and experimental analysis techniques on core
and cuttings samples from the project study area to better determine
rock properties. The results of the experimental techniques were
reviewed and compared to discover whether these methods would
have further application in California and elsewhere to measure
rock properties.
The petrophysical and geological modelling
work included the log analysis, correlation, and mapping work
for reservoir description. Preliminary correlations and maps
were drawn using unprocessed log data, and were refined later
using the results from the log analysis. Physical and chemical
properties gathered from laboratory measurements of conventional
core and cuttings were also used to develop algorithims which
related geological and engineering parameters to log responses.
Some core analysis had been performed previous to the commencement
of this project, and other tests were done as part of this work.
Well log, core and other test data were assembled and stored
in QuattroPro and Excel, commercial spreadsheet packages, which
allowed for easy access and updating and also for uploading to
the project database. Log editing, preparation, and plotting
were done at DPI in the Petrolog system from Crocker Data Processing,
and the analysis was done in Symbiolog. Cross sections and maps
were drawn at MTU using GeoGraphix.
The tasks completed by DPI included:
Acquisition of all log, core, and well history
data available within the study area
Digitizing and data capture of well data
Construction of log database
Analysis of field wells
Correlations of formations and markers
This report discusses primarily the work done
by DPI on this project. Also included is general information
about the geology of the study area and properties of the diatomaceous
rocks that are the principal subject of the work.
3.0 REGIONAL GEOLOGY OVERVIEW
The San Joaquin Basin is roughly coincident
with the southern portion of the geographic San Joaquin Valley
(or Central Valley) of California. It is a downwarped basin with
a total thickness of over 35,000 ft of primarily marine sediments
ranging in age from late Cretaceous to Recent. The basin is bounded
to the east by the Sierra Nevada Mountains, and on the south and
west by the San Andreas Fault and associated structures. The
northern boundary of the basin is a subsurface rise called the
Stockton Arch. The east flank is characterized by gentle dips
and primarily normal faulting. The south and west flanks are
characterized by steep dips and compressional tectonics.
3.1 TECTONICS
Plate margin tectonics have always dominated
the geologic development of western California. Although evidence
in the form of remnant metasedimentary bodies exists for Paleozoic
continental-platform type deposition in California, the earliest
recognizable coherent rock units belong to a subduction-forearc
basin compex that formed during Mesozoic time. Most of the "basement"
rock west of the San Joaquin Valley consists of a melange of metamorphosed
subduction-related rocks called the Franciscan Formation. The
basement to the east of the central valley is granitic, comprising
the roots of the Mesozoic island arc that bounded the subduction
zone. It is not certain where the boundary, and therefore the
continental margin, is located beneath the sedimentary cover in
the San Joaquin Valley. The oldest recognizable sediments are
sand-rich Cretaceous turbidites deposited in the forearc basin.
Turbidites and related deep-water deposits dominated the sedimentary
section until Pliocene time.
In early Miocene time, the oceanic spreading
center that was moving eastward with continuing collided with
the subduction zone and became a transform fault. This fault
or system of faults, collectively called the San Andreas, grew
progressively longer as the triple junctions moved northward and
southward along the coast. This initiated a regime of oblique
compression along the western margin of the basin. This active
tectonic system has been the most significant influence on the
structural and stratigraphic development of the basin from mid-Miocene
time to the present.
Several sets of en-echelon anticlines have
formed along the west and south margins of the basin, all of which
contain oil fields. Because of the rapid syn-depositional structural
growth, the sedimentary sections are characterized by rapid facies
changes and many local and regional unconformities.
3.2 STRATIGRAPHY
The stratigraphy of the San Joaquin Basin is
shown in Fig. 1. This table was taken from Maher, Carter and
Lantz (1975), and the reader is directed to this publication for
an excellent summary of the geology and stratigraphy of the southern
San Joaquin Valley. Formation names used in this table reflect
formal U.S.G.S. usage; as would be expected, there are many informal
local names used for these units throughout the basin.
The sedimentary section is dominated by the
presence of turbidite sands and associated deep-marine shales.
Most of the late Miocene-aged shales are diatomaceous, as are
parts of the Eocene shales. These rocks are the source for most
of California's oil, and under the right conditions also form
reservoir rock. Late Miocene diatomaceous (or siliceous) shales
are the the subject of this study in the Pioneer Anticline area.
3.2.1 NOTE ON DIATOMACEOUS LITHOLOGIES
Diatoms are part of the marine plankton that
make their shells from hydrated amorphous silica (opal). Under
certain conditions, their remains can dominate the pelagic sediments.
These conditions prevailed throughout most of California's sedimentary
basins during most of the Tertiary Period.
In deep basins that are anoxic at depth, the
diatoms accumulate in fine millimeter-scale or thinner layers,
and the organic material is preserved. With burial and heat,
the amorphous opal (opal-A) of the original diatoms is converted
progressively to opal-Ct (opal-cristobalite) and eventually to
quartz. There is a commensurate decrease in rock volume and porosity
and an increase in brittleness. Original opal-A has a real rock
porosity of 60% or more, since there is porosity inside the diatom
shells as well as around them. Opal-Ct has porosity ranging from
35%-45%, and quartz phase rocks can have porosity from 0% to about
25%. None of these phases has much primary permeability, although
fractures in brittle rock provide abundant secondary permeability.
With these ranges of porosity, diatomaceous rocks can have tremendous
storage potential, and by using modern methods of well completion
and stimulation Monterey-type rocks all over California are good
producers. Diatomaceous rocks are discussed in more detail in
Appendiz II.
3.3 GEOLOGY OF THE STUDY AREA
The Pioneer anticline is located five miles
to the southeast of the town of Maricopa on the west side of the
San Joaquin Valley. The east-west trending anticline has surface
expression through areas of Sections 26, 27, 28 and 29 in T11/R23W.
Both flanks are steeply dipping and the top is relatively flat,
with an east-southeast plunge. Several thrust faults trending
sub-parallel to the structural axis have been mapped on the north
flank, including one that cuts several wells and causes a repeated
section. Additionally, several cross faults were recognized that
probably have an oblique-slip sense of motion.
The local names in use in the study area are
noted on the Table 1 and shown in the stratigraphic column for the
Pioneer Field taken from the DOG (Fig. 1a). Stratigraphically, the deepest
wells in the study area are within the Pioneer Field and penetrate
several thousand feet of the Temblor Formation. The overlying
Monterey, Reef Ridge, and Etchegoin Formations were the study
intervals for this project. The San Joaquin and Tulare Formations
are present, but were not studied.
The Temblor Formation on this structure consists
of a thick (at least several thousand feet) accumulation of sands
and interbedded shales with a bedding thickness of ten to fifty
feet. The trap for the Pioneer Field and other Temblor accumulations
in the area consists of cross faults perpendicular to the anticline
that juxtapose interbedded shales against sands, creating a series
of thin stacked oil columns distributed over a large interval.
Overlying the Temblor sands are a series of clay shales and silty
sands that may represent the Gould and Devilwater Shale equivalents.
Above this is a section that is about 1500 feet thick in the
Pioneer Field area itself that consists of several intervals of
siliceous shales interbedded with clay shales representative of
the Monterey Formation. Down structure this section thickens
and probably picks up some overlying Reef Ridge Formation, although
it is difficult to tell the Monterey and Reef Ridge apart without
paleontological assistance. The post-Miocene unconformity cuts
the Monterey/Reef Ridge section, and it is probably deeply eroded
near the structural crest. Overlying the unconformity are silty
sands and gray clay shales of the Etchegoin Formation. The Etchegoin
greatly thickens downdip. Another unconformity tops the Etchegoin,
and this is overlain by the undifferentiated coarse sands and
interbedded shales of the San Joaquin and Tulare Formations.
Structural growth has had a profound influence
on the stratigraphic section. There is an angular unconformity
present at the top of the Reef Ridge Formation, part of the widespread
post-Miocene unconformity. Another unconformity is usually mapped
at the top of the Etchegoin Formation. Substantial section must
be missing across one or both of these discontinuities, since
the diatomaceous rocks of the Monterey and Reef Ridge Formations
are at a higher diagenetic grade than their present depth of burial
would normally allow. This is discussed further in Section 4.2
and Appendix II. As a result of structural deformation, the oil-bearing siliceous
shales of the Monterey and Reef Ridge Formations subcrop beneath
younger rocks on the anticline. The oil that is produced throughout
this part of the basin from Pliocene rocks is believed to be sourced
from these subcropping Miocene shales. Pliocene outcropts to the west of the
crest of the structure have been mapped as having oil stain adn tar on bedding
planes. This oil very likely migrated from the aforementioned subcrops.
3.3.1 EXISTING FIELDS AND PRODUCTION IN
THE STUDY AREA
3.3.1.1 PIONEER FIELD
The Pioneer Field itself includes about half
a section of productive acreage in Section 32, T11N/R23E. It
was discovered in July 1959 and as of the end of 1993 had produced
a cumulative of 194,488 bbls. of 37-38°
API oil from the Temblor Formation. The reservoir sands are tentatively
assigned to the Media/Carneros equivalents. Two wells are still
capable of production, of which one is currently on, averaging
approximately 7 BOPD with a 16% water cut.
A small amount of Miocene production has been
obtained in the Pioneer Field and vicinity, although most of the
wells were not formally assigned to the field. In 1980 and 1981,
Tenneco drilled six wells on the north flank of the anticline,
about two miles northwest of the old Temblor producers. These
wells were completed in the Monterey for a low daily rate of flowing,
gas-charged heavy oil production. The production was uneconomic
and the wells were idled. In 1990, another well was drilled in
a different structural position, near the old Temblor wells on
the crest of the structure. This well encountered similar conditions
to the six Tenneco wells, and is still being produced at low rates.
3.3.1.2 LOS LOBOS FIELD
The Los Lobos Field, located about one mile
north of the Pioneer Field, was discovered in 1952. Because of
the 70o dips on this flank of the anticline, the wells
are distributed in a line one well wide and about two and a half
miles long. On the west end, it produces from a turbidite channel
sand in the upper Reef Ridge Formation and on the east end from
a sand in the overlying Etchegoin Formation. Productive depth
ranges from about 6000 ft to nearly 8000 ft over a narrow horizontal
range because of the dip. The field is now abandoned.
3.3.1.3 OTHER DRILLING
A number of exploration wells were drilled
in the Pioneer area in the 1930's through 1950's, resulting in
the discovery of the Pioneer and Los Lobos Fields. More drilling
followed during the 1950's and 1960's, but no further discoveries
were made. In the 1970's and 1980's, Tenneco (who held nearly
all the land in the area) drilled several deep tests which were
quite useful to this project. Many wells have had shows in the
Monterey and in some cases were tested. A summary of shows in
the more important wells is shown in Table 2.
3.3.2 THE ETCHEGOIN AND REEF RIDGE/MONTEREY
IN THE PIONEER AREA
Although the main focus of the project was
the siliceous shales of the Reef Ridge/Monterey section, the overlying
Etchegoin Formation was included in the analysis. In this area,
the upper part of the Etchegoin consists of a gray to gray-green
clay shale overlying silty sands interbedded with shales. The
section is 100 feet or less in thickness on the crest of the anticline,
and thickens down the flanks. Changes in thickness result from
a combination of erosional removal from the top and syndepositional
growth of the anticline. Etchegoin sands are productive in the
eastern part of the Los Lobos Field.
The Reef Ridge/Monterey section includes a
channel sand in at the top that is present only in the western
part of the Los Lobos Field, where is formed the main producing
interval. Elsewhere, the lithology consists of fairlly clean
diatomaceous rock interbedded with more clay-rich shales.
The major correlations of formation tops were
readily visible on the unprocessed logs, and the top Etchegoin,
top Miocene, Reef Ridge channel sand, and top Temblor were all
identified prior to the availability of the petrophysical results.
These tops were needed to assist in parameter selection and zonation
of the wells for the log analysis phase of the work. Within the
Monterey itself, however, few internal correlations could be recognized.
In the past since the siliceous shales are difficult to correlate
from raw paper logs, workers have picked the top Miocene unconformity
upon which to base all their mapping, although it was well known
that the pre-unconformity Miocene structure probably was quite
different. If the shales could be correlated internally, structures
could be identified that might lead to the discovery of new pools.
In the wells from the Pioneer area, it was
possible to identify one correlation in the Miocene from the raw
logs: the point labeled "R" on the type log (Fig. 1b).
This is the top of an interval where the resistivity is more
"spiky" than it is in overlying intervals. This probably
indicates an increase in carbonate stringers, one of the typical
Miocene lithologies. Above the "R" marker, however,
it is difficult to trace correlations on raw logs. The additional
correlations shown on the type log were made using the computed
results. They show that the intervals of cleaner and shalier
siliceous rocks can be traced throughout much of the study area,
although their character changes somewhat from well to well.
A stratigraphic cross section hung on the top Miocene shows these
correlations in an approximate strike view along the north flank
of the structure. Fig. 2 uses only raw logs, and Fig. 3 uses
the computed logs.
The exercise of correlating the Miocene shows
the value of using both the raw logs and the computed results
for geological correlations. It is necessary to perform preliminary
correlations on the raw logs, since formation/lithology boundaries
are used in the petrophysical parameter selection, but it is important
to go back and refine the correlations by using the results from
the log analysis.
4.0 METHODS USED IN THIS PROJECT
At the start of this project, a data search
revealed that no core material remained in existence for the Monterey
section within the study area, although core analysis data from
one well and cuttings from another were available. Therefore,
to obtain rock material for experimental analysis, the project
obtained permission from Unocal Corporation to utilize the core
and logs from two wells within the diatomaceous reservoir in the
Cymric Field, 25 miles to the northwest.
4.1 CYMRIC ANALOG
Wells in the Cymric field which were completed
in the siliceous shales were reviewed in terms of completion technique,
production performance, hydrocarbon concentration and reservoir
rock quality to determine their suitability for use as an analog
for diatomaceous production from the Pioneer Field area.
The Reef Ridge reservoir in the Cymric Wellport
pool had produced a cumulative of 961,819 bbls. at 12.6°
API oil and 13.38 mmcf gas as of 1993. Current production is
2,653 BOPD, with an average 72.6% water cut. Since discovery
in 1957, 151 wells have been drilled to an average well depth
of 3500 feet. Fifty-six wells are on production and 55 wells
are shut in. This reservoir is somewhat unusual for Monterey-type
production in the San Joaquin Valley in that it produces heavy
oil from both the Opal-A and Opal-Ct phases. Most production
elsewhere is from either the Opal-A or quartz phases, and is generally
20o API or higher. The Cymric Field is a good analog
for the Pioneer Field production since the Monterey at Pioneer
is also in the Opal-Ct phase and produces heavy oil.
The detailed core analysis and log data from
the Cymric cores were used in setting up the analysis model for
the Pioneer area. The most extensive Cymric data in Well #418
included a long section of Opal-A phase rock, some Opal-Ct, and
the transition between them. The data from the deeper Well #415
included spot cores down to nearly 5000 ft. However, the lithology
penetrated by the #415 was more clastic than diatomaceous in the
lower intervals and therefore quartz-phase diatomite was not represented
in the available core samples. The rocks at Pioneer are primarily
in the Opal-Ct to quartz phases, with only a small amount of the
section in the lower Opal-A phase range. However, the Cymric
data were used to calibrate the Opal-A end of the model.
4.2 LITHOLOGIC AND CORE DATA AVAILABLE
Much of the lithologic data for the project
came from the extensive analyses, descriptions, photographs, and
personal inspections by team members of the Cymric analog core
wells, Unocal #415 and #418. This included thin section and SEM
photographs work done at MTU as part of the project. However,
although no core material could be located for wells in the Pioneer
area, reports on analyses done on the core from Tenneco #62X-30
were available. Additionally, Tenneco performed some detailed
analyses on well samples, probably sidewalls, taken from two other
wells in the area. Summarized below are the results from the
Tenneco special analysis study.
Eight samples of the Antelope Shale taken from
various wells in T11N/R23W were examined by Tenneco in 1980.
The objective of the examination was to determine the mineralogy
and degree of natural fracturing for each well.
The wells were located approximately 1.7 miles
apart and were at structurally different depths. Results of the
analysis indicated significant lithological differences between
each well.
The samples from the Santiago (A) 72-30 well,
in which the top Miocene is located at -257 feet subsea, consisted
of a diatomaceous siltstone showing very little structure or fabric.
Localized concentrations of detrital material included quartz,
feldspar, altered rock fragments and detrital clay. Volcanic
glass and calcareous microfossils were also identified, with pyrite
fillings developed within some of the calcareous microfossils.
Siliceous microfossils and glass shards are present in some samples
and show no indications of dissolution.
The samples from the Santiago "C"
55-28 well, in which the top Miocene is at -2258 ft subsea, in
contrast, was comprised of very finely laminated shale. Concentrations
of pyritized diatoms other siliceous microfossils were absent
or rare. Numerous microfactures dissected some of the samples
but were healed by an isotropic fracture filling identified as
amorphous silica. Some fracture fillings were composed of cristobalite.
Open microfractures were not observed.
In summary, the samples from the Santiago "C"
wells are very different from those of the Santiago "A"
well. The "C" well is more strongly cemented which
has resulted in the sealing of any microfractures which could
have existed in the "C" well. Similar fractures are
open in the "A" well. These naturally-occuring fractures
are high-angle and indicative of compression. The fractures are
closely-spaced and numerous and are the main conduit for hydrocarbon
production. In contrast, the "C" well exhibits significantly
less fracturing. High angle compression fractures are present,
but more widely spaced. However, the rocks in the "C"
well are at a more advanced stage of diagenesis and are more brittle,
so continued tectonic movements are likely to continue fracturing
the rock.
The samples were subjected to both acid exposure
and simulated steam injection tests. Samples from the Santiago
"C" well were very resistant to acid attack and remained
intact, while the "A" well samples experienced various
degrees of mechanical degradation.
The simulated steam injection tests had no
effect upon the Santiago "C" samples and showed no signs
of hydrocarbon displacement. Santiago "A" samples,
however were broken down by steam injection with the maximum breakdown
occurring in samples at depths between 1377 and 1394 feet. It
was concluded that the degree of breakdown is directly related
to the volume of smectite in the fine size fraction.
Potential reservoir problems were identified
as a result of the laboratory tests and are summaried as follows:
1. The changes in mechanical strength of the
Antelope shale is a direct result of variations in silica cementation.
Santiago "A" 72-30 has low strength and will have
low embedment pressure. Packing of induced fractures will present
difficulties. The strength of the shale in the Santiago "C"
55-28 well will be high, as will the embedment pressure.
2. Acid sensitivity in the "A" well
suggests potential for damage due to the secondary precipitation
of iron compounds.
3. Fresh water sensitivity will be a major
problem in Santiago "A" due to smectite clay. Steam
injection tests demonstrate a large degree of disaggregation.
The properties of the Antelope shale in the "C" well
will be unaffected.
The lithology of the siliceous intervals in
both wells is typical of the diatomite in this area, with clay
content varying from 10% to 30%.
4.3 ANALYSIS APPROACH FOR THIS STUDY
DPI has established a procedure for performing
petrophysical field studies that was used to organize and guide
the work on this project. This procedure is discussed below.
A modern petrophysical field study that is
properly performed has very significant implications for reservoir
management. Although advances in tool design and the development
of new analysis techniques have improved our ability to assess
reservoir potential, the most important aspect of a modern field
study is an integrated analytical approach.
The elements of an integrated analysis are:
- Development of a predictive model for the
entire field (field function)
- Preparation of a standard dataset for uniform
processing
- Model parameter selection based on reservoir
geology
- Engineering and production data incorporated
where known
- Use of a detailed plan for all studies that
is adapted to specific project needs
DPI has used an integrated analytical approach
for the Pioneer Anticline study. The elements are further discussed
in Appendix I.
4.3.1 OVERVIEW OF DPI PROJECT TASKS
The primary purpose of this study was to perform
a reservoir description to be used as an example in demonstrating
the use of PC-based evaluation and visualization software. As
part of this effort, DPI developed a petrophysical model that
would be predictive of water saturation, porosity, shale, and
clay volume in the Pioneer area. DPI also performed stratigraphic
correlations and structural mapping to provide a basis for computerized
visualizations of the structure and stratigraphy.
Well data were acquired and digitized. Since
no core material was available from the Pioneer area, the project
secured the release of extensive core material and analysis data
from two wells in the Opal-A/Opal-Ct heavy oil reservoir in the
Cymric Field. These cores provided samples for laboratory analyses
at MTU and also calibration data for the Pioneer analysis model.
At DPI, the well data were edited, depth shifted
where applicable, and standard environmental corrections were
applied. Log normalization was done, then a foot-by-foot computerized
analysis was run on all project wells that included a significant
section of Etchegoin and Reef Ridge/Monterey Formations. For
the wells that had modern resistivity and porosity logs (full
log suites), it was possible to use standard petrophysical models
to derive values of lithology, porosity, and saturation. Many
project wells had only old electrical logs, however, and it is
not possible to apply standard models to these wells. Based on
the analytical results in the full suite wells, DPI developed
an empirical model to derive lithology and porosity for these
wells. It is not possible to compute a resistivity-based water
saturation value from an electric log, since the old deep-reading
curve is strongly asymmetrical in its response and standard machine
processing is invalid. Therefore, no saturation calculation was
performed for these wells.
These data were used to test various computer
software packages for their usefulness in a small-company setting
to perform reservoir description with PC-based tools. Most of
the software testing was done by MTU staff using data generated
by DPI and by MTU.
4.3.2 PETROPHYSICAL MODEL: DUAL WATER
Conventional interpretation models have not
proven reliable for quantifying porosity, water saturation, and
clay volumes in most San Joaquin Valley oil fields. Classical
models such as Simandoux, Dispersed Clay, Laminated Clay, or Indonesian
have yielded erroneous results in similar reservoirs due both
to inadequacies of the models and improper parameter selection.
The Dual Water model, while theoretically sound, can also yield
erroneous results if parameters are improperly selected.
The model used in this study is unique and
proprietary to DPI in that published equations have been applied
in software written by DPI and in other systems that are commercially
available. The model is based upon interpretation models generally
accepted throughout the industry. The sequence of interpretation
steps within the model is crucial to an accurate computation.
Improper sequencing of otherwise correct equations will result
in error where measurements require both shale and hydrocarbon
corrections. Clay volume is first computed from each desired
indicator. The minimum, median, or average clay volume is then
determined as desired. Clay-corrected porosity is computed and
iterated for hydrocarbon corrections. The hydrocarbon saturation
of the invaded zone is computed on each iteration. Water saturation
is then computed either by a quadratic form of the equation or
by using an iterative method where 'n' is not equal to 2.0. The
formation factor porosity exponent 'm' in the saturation equation
is not a constant in the Pioneer area model, but is a variable
as a function of lithology.
The model is discussed further in Appendix
I.
4.3.3 WORK SEQUENCE
The work sequence followed in this project
conforms to the Field Study Management template prepared by DPI.
The only exceptions to the guidelines occurred when certain project-specific
technical issues required further investigation outside the scope
of the general Field Study outline. The main segments of the
sequence are:
- Database preparation and editing
- Environmental corrections
- Normalization
- Log correlation
- Parameter selection
- Verification of analysis and sensitivity
runs
- Identification of analysis problems
- Final analysis
- Verification of correlations with analytical
results
- Zone summations
- Mapping of zone tops and properties from
the zone summations
- Final report
4.3.4 DATABASE PREPARATION AND EDITING
The database construction consists of: locating
well data, creating tracking spreadsheets for each well, digitizing
paper logs, editing data, depth shift and verification, environmental
corrections, and normalization. The database was prepared for
both the petrophysical analysis and for the geological interpretation.
4.3.4.1 DATABASE CONSTRUCTION
Pre-existing digital data were not available
on any wells, therefore the paper logs were digitized. The curves
were edited to remove invalid data, and then depth shifted where
necessary. Header data and drilling zone information were also
entered for each well.
Standardized curve nomenclature was used throughout
the database preparation phase to ensure the maximum efficiency
of batch processing later. A lexicon of curve names is included
in Table 2. It is important, however, to retain the actual name
of resistivity curves so that the type of tool can always be identified.
A second set of resistivity curves was created in each well that
consisted of copies of the original curves with uniform names
for use with cross section programs.
4.3.4.2 ENVIRONMENTAL CORRECTIONS
The appropriate chartbook corrections were
applied to the induction, gamma ray, neutron, and density logs.
No similar corrections exist for old electric logs.
4.3.4.3 NORMALIZATION
Normalization was made difficult in this study
by the large area, the structural and lithologic changes, and
the scatter of the well data. A full discussion of normalization
procedures is provided in Appendix III, Section AIII.1.4.
4.3.5 PARAMETER SELECTION
Parameter selection was challenging for this
project due to the need to develop a useful model both for full-suite
wells and for E-log only wells. Parameter selection proceeded
in three stages: calculation of clay volume, calculation of porosity,
and calculation of water saturation. The parameter selection
process is discussed briefly in the following sections and in
Appendix IV.
4.3.5.1 CALCULATION OF CLAY VOLUME
Volume of clay was computed by applying a non-linear
transform to the baseline-shifted SP curve. For a few wells with
poor SP's, clay was computed from the shallow resistivity curve.
Very little quantitative data were available to calibrate the
clay transform, so it was set up principally by the interpretation
of descriptive data from core and mudlogs, local knowledge, and
geological expertise. Details of this procedure are discussed
in Appendix IV, Section AIV.1.1.
4.3.5.2 CALCULATION OF POROSITY
On full-suite wells, total and effective porosity
were computed from the neutron-density crossplot after application
of an iterative light-hydrocarbon correction. The model was calibrated
to whole core porosity and verified with available sidewall core
data. All core porosities are assumed to represent values close
or equal to total porosity, since the samples were analyzed using
the Dean-Stark procedure. No data were available to correct the
measured laboratory data for the effects of overburden, so whole
core porosities tend to be somewhat higher than computed values.
For the E-log only wells, an empirical depth function was developed
for total porosity based on the computed values from the full-suite
wells. Effective porosity was then computed as a function of
total porosity and clay volume.
Total porosity is computed from the crossplot
by projecting the data points onto the matrix line along a certain
slope, defined by a line between the matrix point and the dry
clay point.
Details of the porosity model calibration are
presented in Appendix IV, Section AIV1.2.
4.3.5.3 CALCULATION OF WATER SATURATION
After establishing good Vclay and porosity
transforms, calculation of water saturation was performed. Some
core analysis and mudlog data were available to assist in model
calibration. Water saturation results are only available for
full-suite wells, since the old lateral logs in E-log only wells
are invalid for the calculation of a foot-by-foot water saturation.
Methods exist for hand calculating the correction for the lateral
logs to true resistivity as an average over an interval, if the
bed is thick enough to allow the tool to read properly, but in
the siliceous shales the bedding is far too thin for these tools
to be valid. Other methods exist for deconvolving these curves
based on tool response physics, but any of these resistivity-log
corrections were beyond the scope of this project and were not
done. Water saturation was determined using the relationship:
where:
Fo = Dual Water formation factor
This is the published form of the Dual Water equation as presented
in the Schiumberger literature.
The calculation of water saturation is discussed further in Appendix
IV, Section A.IV.1.3.
5.0 RESULTS OF THE STUDY
This project was not typical of most reservoir
descriptions in that the results were not intended to be used
for any economic purpose within the context of the project itself.
The main result of DPI's portion of this study is the digital
log database, the analysis, the geological correlations, and the
methodology for actually performing the work. Some observations
and conclusions can be drawn from the study, however, and they
are discussed below.
5.1 OBSERVATIONS AND CONCLUSIONS
A model has been developed to allow the use
of old E-logs and other wells lacking porosity data in an integrated
reservoir description project for diatomaceous reservoirs. Such
a model must be calibrated to each individual field and reservoir
by including all available modern log and rock properties data.
It is also important to note that the E-log only model depends
heavily on a geologically-based rule set. The geologist/log analyst
is performing an interpretation that must come form personal knowledge of the area
when he/she sets up an old E-log for processing, so it is best if the
petrophysics is done by the project geologist. If this is not possible,
the petrophysicist should at least work very closely with
the geologist when performing this kind of field study.
Nearly all basins in this country have a large
number of old E-log wells, even if they also have many newer wells
with porosity logs. The E-logs are always used by the geologist
for correlation, even if they are ignored by the petrophysicist
in performing log analysis. This approach can serve as a guidepost
for the integration of the old log data into the quantitative
reservoir description.
The Miocene diatomaceous section analyzed in
this project is widespread throughout the southwestern San Joaquin
Valley. The reservoir description work resulting from this effort
will have application to a much larger area that is prospective
for oil production. With the recent increase in oil price and
level of effort in California, these results may have a significant
impact on future activities in this part of the basin.
There were anomalies in the water saturation
results that suggest water resistivity variations exist within
the study area that could not be identified with the data available.
This is probably not surprising, since the Monterey was probably
deeply flushed with meteoric water during exposure at the end
of Miocene time. Also, it is well known that diagenesis of feldspathic
sands in the San Joaquin Valley has a significant effect on the
chemistry of connate waters. Either or both of these processes
could have large and unpredictable effects on water resistivity
within the reservoir.
5.2 OUTPUT DATA INCLUDED WITH THE REPORT
The output product of this study delivered
to MTU by DPI consists of several kinds of digital data and this
written report. These deliverables are discussed below.
5.2.1 FINAL REPORT
The final report consists of a brief summary
of each analysis step and issue involved in the study, followed
by a full discussion included in the Appendices. Appendix V
contains all figures and illustrations to which the text refers.
5.2.2 FINAL DATABASE
The final database for this project area consists
of raw curves, depth shifted, and environmentally corrected curves,
and a number of computed curves. The computed curves fall into
two families: final model outputs and intermediate process curves
used as model inputs. These are tabulated and defined in Table 3.
Other digital data delivered include a spreadsheet
of well information and correlations by well. Previously DPI
has delivered a set of hand-drawn cross sections and maps to MTU
for use in setting up computerized displays in GeoGraphix and
other systems.
6.0 DISCLAIMER
All interpretations are opinions based on inferences
from electrical or other measurements made by third parties and
we cannot, and do not, except in the case of willful negligence
on our part, be liable or responsible for any loss, costs, damages
or expenses directly or indirectly incurred or sustained by anyone
resulting from any interpretations made by any of our officers,
agents, or employees. These interpretations are also subject
to our general terms and conditions as set out in the current
Digital Petrophysics, Inc. price schedule, which are incorporated
at this point as though set forth at length.
APPENDIX I
Background Information
AI.2.1.1 ANALYSIS APPROACH
The integration of all available reservoir
information, viewed from a strong geological/production engineering
standpoint, combined with modern and theoretically sound petrophysical
analysis techniques is the overall philosophy of field study management
that guides DPI's approach to projects such as the Pioneer area
study. The basic goal of the analysis is the development of a
field function: a petrophysical model that can be used to derive
a consistent set of computed parameters for every well. If the
field function is properly calibrated and if the database is consistent,
it can then be used to interpret other wells in the project area
that are determined to be similar.
Every effort is made to construct a consistent
database for the project, using uniform curve nomenclature, the
same preprocessing procedures such as depth shifting and environmental
corrections, and careful normalization to adjust tool responses.
These steps are all described in detail in this report in the
various sections included in Database Preparation, Section 2.2.2,
and Appendix III. The key wells from this database, usually core
wells, are used for calibration of the model, and parameter selection
is performed and verified on them. This phase of the project
is very time-consuming, but the model analysis can be quickly
extended to the rest of the field wells when the database is consistent,
thus saving a great deal of time on the processing of the entire
project.
No field study database contains definitive
information for all necessary reservoir parameters required by
a petrophysical model. Most of these are derived from laboratory
analyses on core material. These analyses must be graded on the
basis of the procedure used, sample quality, and overall validity
of the data. Most of the model parameters are based on the geological
characteristics of the reservoir, such as mineralogy, grain size,
sorting, and stratigraphy. DPI utilizes geologist/petrophysicists
experienced in oilfield production operations for selecting model
parameters. Even where excellent core data exist, the ultimate
model calibration must be performed by the experience of the analyst,
based not only in previous petrophysical work but in a background
of sedimentary and reservoir geology. The clay and porosity transforms
in particular are judged by how well they fit the known mineralogy,
depositional environment, and diagenetic history of the sediments.
It is also very important whenever possible
to incorporate local expertise on the geology and reservoir conditions
from staff personnel who are most familiar with the field. In
the case of this project, DPI staff had already worked in the
area and had a good knowledge of the reservoir.
DPI has developed a set of detailed guidelines
for field study management. All the necessary steps for execution
of a field study are listed in their proper order. However, the
system is flexible and can accommodate additions and changes in
project direction and scope as technical issues are identified
that alter the original plan. Without the guidelines, steps could
easily be forgotten, performed incorrectly, or out of sequence
when events occur that disrupt project flow.
Nearly all field studies include several elements
that are almost research in nature, and often result in new ways
of viewing the reservoir. These are explained fully in DPI's
final report, along with a detailed record of all procedures,
events, and results from the study. The product of this is an
interdisciplinary tool that contains raw data, petrophysical computed
parameters, and an interpretation of the analyzed data.
AI.2.2.1 PETROPHYSICAL MODEL
AI.2.2.1.1 CHOICE OF MODEL
Classic approaches to shaly sand analysis such
as SARABAND's laminated-dispersed logic (Poupon et al., 1970)
are unstable under a variety of conditions including very low
porosity gas sands, feldspathic sand and silt sequences, and heavily
cemented sands. Without logging tools that recognize thin beds,
such as raw dipmeter or various micro resistivity measurements,
it is not possible to distinguish between laminated and dispersed
shales. Therefore, a dispersed-shale model was chosen for this
study. Of these, the Dual Water and Waxman-Smits models are preferred
because they are theoretically sound. Insufficient information
was available to calibrate the Waxman-Smits model properly, so
the Dual Water model was used in this study.
AI2.2.1.2 POROSITY MODEL
Porosity was determined from the neutron-density
crossplot method for shaly sands for all the wells with porosity
logs. A matrix density curve was computed and used instead of
a fixed point in this crossplot calculation, since the matrix
endpoint varies in diatomaceous rocks from less than 2.0 g/cc
up to more than 2.75 g/cc, depending on the degree of diagenesis,
clay content, and dolomitization. Hydrocarbon corrections were
applied on an iterative basis to the density and neutron data
for computation of total and effective porosity. The correction
is computed by iteration until the porosity change is within a
certain tolerance (or until a certain number of iterations have
been done). The overall correction applied was that for a low-gravity
API oil, which results in very little correction. In diatomaceous
rocks, neutron-density crossover does not necessarily indicate
gas, but is merely a function of lithology in Opal-A and Opal-Ct.
The calculation of the hydrocarbon correction
was complicated by the absence of an Rxo measurement in most of
the wells. Therefore, Sxo was computed from Rt using a quadratic
solution of the Dual Water equation and an exponent as follows:
AI.2.2.1.3 SATURATION MODEL
Where 'n'=2, the Dual Water model can be solved
quadratically. Where 'n' <> 2, the solution is iterative.
The model repeats the iteration until the solution converges
within an acceptable user-defined limit, or until a set number
of iterations has been performed.
The choice of electrical properties for the
saturation model was quite a complex and involved procedure due
to the unusual nature of the reservoir, the small amount of useful
core data, and the problems to be solved. The porosity exponent
"m" and the saturation exponent "n" were both
variable functions of lithology. Also, the Rw value was difficult
to identify, and it is likely that there are some water resistivity variations
that could not be identified with the available data. Calibration
procedures are discussed in detail in Appendix IV, Section AIV.2.2.4.3.
APPENDIX II
Characteristics of Diatomaceous Rocks
A.II.1.0 MONTEREY SHALE FACIES
AND PRODUCTION CHARACTERISTICS
The characteristics and evolution
of the siliceous shale facies of the Miocene Monterey formations
are complex and have caused consternation among many operators
since they were first found to be productive. The Monterey can
be found productive at any depth. However the characteristics
of the reservoirs vary dramatically with depth and clay content.
A clear understanding of the depositional and diagenetic process
involved in the formation of these reservoirs is necessary in
order to appreciate the potential of the biogenic shale reservoirs
at Pioneer Anticline and elsewhere in the San Joaquin Valley.
A.II.1.1 FORMATION OF A DIATOMACEOUS
RESERVOIR
Diatoms are marine planktonic plants
that form their shells from hydrated amorphous silica, or Opal-A.
At the time of deposition, the hydrated amorphus silica is composed
of one molecule of SiO2 bound with a number of H2O
molecules. Under certain conditions diatoms dominate the plankton
in open-sea areas and, where clastic input is minor, deposits
of nearly pure diatomite can be formed admixed with a small amounts
of silt and clay. The combination of normal intragranular porosity
and the void space inside the hollow diatom shells can yield a
bulk porosity of up to 75% in unaltered (Opal-A phase) diatomite.
However, due to clastic contamination and compaction at even
shallow depth, the porosity is normally in the 55%-65% range.
The grain size is very small and the permeability is low, usually
less than 1 millidarcy. Figure A.II-1 shows a scanning electron microscope
(SEM) photograph of pristine Opal-A diatom frustules. The rock
is rigid but friable. With the high matrix porosity, reservoir
fluid storage potential is very large.
Under moderate heat and pressure,
the unstable amorphous opal (Opal-A) of the diatom tests begins
to convert to a microcrystalline form of quartz called Opal-Ct
(Cristobalite). Through compaction and morphological changes
related to the formation of Cristobalite, most of the diatom tests
lose their intricate structure and take on the appearance of watered
down corn flakes. Thus, most of the individual diatoms are no
longer distinctly recognizable as fossils. There is a consequent
large loss of rock volume and porosity, although a typical Opal-Ct
still has a porosity of 40%-45%, high by conventional standards.
Such rocks have significant matrix reservoir storage. Figure
A.II-2 shows an SEM photograph of Opal-CT.
With greater heat and pressure,
the Opal-Ct converts to quartz, resulting in an additional loss
of rock volume and porosity. With enough heat and pressure, very
clean diatomites end up as glassy chert with no matrix porosity.
Under the right tectonic conditions, the glassy chert can be
extensively fractured, thus providing a very high permeability
reservoir. Such reservoirs may have little or no matrix storage
but can have exceptionally high fracture porosities. Quartz phase
rocks with admixed clastics retain some matrix porosity, and consequently
have potential matrix storage for hydrocarbons. Intermediate
stages of diagenesis yield a rock with moderate to low (15% to
20%) porosity which is very brittle and readily fractured. The
term porcelanite is generally applied to quartz phase diatomite
having low to moderate amounts of clay and moderate porosity.
Below the Opal-Ct phase window,
the rock alters gradually to quartz phase, generally over a long
interval. At Lost Hills and South Belridge, the quartz transition
in the clean facies starts around 4,000 feet subsurface. Remnant
Opal-Ct may be present in some places as deep as 5,500 feet, but
the majority of the rock having low clay content is in the quartz
phase by 5,000 feet. In some more tectonicaly active structures,
prior depth of burial and subsequent erosion have brought Ct and
quartz facies to shallower depths or to outcorp. If the diatomite
was relatively pure, its quartz-phase equivalent endpoint is glassy
chert. However, the transition from porous quartz phase clean
diatomite to glassy chert can be over many thousands of feet,
depending upon temperature and pressure. In the San Joaquin Valley,
there is very little glassy chert but there are vast volumes of
brittle porcelanite that was originally diatomaceous shale having
low to moderate clay volume. The shale usually has streaks of
pure porous quartz or chert, and often retains matrix porosity
to relatively great depths. Quartz-phase rock retains both micro-
and macro-fractures much better than Opal-Ct phase rock.
Recent developments around the San
Joaquin Valley and better understanding of existing production
from Monterey-type reservoirs indicate that the quartz-phase reservoirs
can be excellent producers under certain circumstances. The rock
must be clean enough to be brittle and must be subject to significant
tectonic stress to propagate extensive macro fractures. Abundant
additional reserves are possible where the rock retained sufficient
matrix porosity and/or micro fractures to store hydrocarbons.
Production from the Monterey in
coastal oil fields is often from fractured glassy chert having
little or no matrix storage. However, fracturing in these reservoirs
is so intense that the fracture storage is much higher than that
found in most San Joaquin Valley deposits.
The transition between diagenetic
phases is gradational and is partially dependent on clay content.
The Opal-A/Opal-Ct transition in low clay environments usually
occurs between depths of 1700 - 2500 ft. The presence of clays
retards the Opal-A to Ct conversion, so in a section with interbedded
clastics the transition could be stretched over an even longer
interval. The Opal-Ct/quartz transition is more variable in depth
and can extend as a mixed facies over several thousand feet.
However, for clean diatomite (low clay), the transition occurs
between 4,000 and 5,000 feet along the west side of the San Joaquin
Valley.
Diatomaceous rocks become more brittle
as they reach higher diagenetic grade, culminating in pure quartz
cherts that shatter like glass. Brittleness and susceptibility
to fracturing decrease with increasing clay content. When these
diagenetically embrittled rocks are deformed in the young, tectonically
active structures common on the west side of the San Joaquin Valley
they fracture readily. Therefore, fracture permeability is common
and greatly enhances the productive capacity of the rocks. Fracture
stimulation in wells is often used in these reservoirs to facilitate
the interconnection of the existing microfracture network and
access the large matrix and micro-fracture storage capacity.
A.II.1.2 ANALOGOUS SILICEOUS
SHALE RESERVORS IN THE SOUTHWESTERN SAN JOAQUIN BASIN
Nearly all reservoirs of upper to
middle Miocene age in the Southwestern San Joaquin Valley are
either turbidites or biogenic siliceous shale. They are found
in formations commonly referred to as the Reef Ridge, the McClure/Antelope
Shale, and the McDonald Shale. There is economic production from
the siliceous shale facies of one or more of these formations
in fields such as Lost Hills, North and South Belridge, and Buena
Vista Hills. Some of the reservoir characteristics of these formations
are summarized below.
A.II.1.2.1 REEF RIDGE FORMATION
The Reef Ridge (Miocene) consists
of moderate to very clayey diatomaceous shales. In the crestal
portion of the Lost Hills and South Belridge fields, the Reef
Ridge is in the Opal-A phase and responds well to fracture stimulation.
Further down the structure, the transition to Opal-Ct results
in lower productivity in the clay rich zones. However, in some
intervals having lower clay content, the Opal-Ct responds with
good production rates of oil and associated gas.
A.II.1.2.2 MCCLURE/ANTELOPE SHALE
FORMATION
The McClure (Antelope) Shale (Miocene)
is similar in nature to the Reef Ridge. Deposition in the vicinity
of the Lost Hills and South Belridge fields during Reef Ridge
and McClure times was dominated by diatom blooms during periods
of varying clastic influx. Diatom bloom cycles which were contemporaneous
with periods of low clastic influx resulted in relatively clean
diatomites. Late in the McClure times, diatom deposition was
high and clay influx was low, thus yielding several hundred feet
of fairly clean diatomite with low clay and silt content. At
Lost Hills, this clean interval is the Cahn Zone. The occurrence
of limestone or dolomite lenses is more common in the McClure
than in the Reef Ridge.
A.II.1.2.2.1 CAHN ZONE OF THE
MCCLURE/ANTELOPE SHALE FORMATION AT LOST HILLS
DPI classifies the Cahn Zone as
being the low clay diatom rich interval which is easily correlated
on neutron-density porosity logs over the entire Lost Hills structure.
This zone has a very low clay content and represents a period
of locally intense diatom deposition with very low clastic influx.
The Lost Hills Cahn Zone has similar characteristics to the clean
intervals at Pioneer.
The Opal-A/Opal-CT and the Opal-CT/quartz phase
boundaries in Lost Hills have subsea depth
windows of 1,800 to 2,300 feet and 4,300 to 5,000 feet respectively.
At Southeast Lost Hills there is strong evidence that individual
well production is a function of the thickness of the clean facies and
the degree of natural fracturing.
A.II.1.2.2.2 MCDONALD SHALE RESERVOIRS
AT LOST HILLS
The McDonald Shale is productive
on the southeast plunge of the Lost Hills anticline. The clean
diatomite facies in the McDonald may be clayer than the clean
facies in the Cahn zone above. Also, the McDonald contains a
great number of limestone or locally dolomitic layers ranging
in thickness from a few inches to a few feet. These layers may
be locally fractured and contribute to production
A.II.1.3 FRACTURING
The more prolific biogenic shale
reservoirs of the Monterey produce from a system of natural micro
and macro fractures which drain the primary pore system. The
macro fractures are tectonically induced. The micro fractures
can be derived from both tectonic and diagenic causes. Micro
fractures, and to a lesser extent macro fractures, can be healed
or closed off by precipitation of cementing agents or by plastic
deformation of the matrix.
A.II.1.3.1 MICRO FRACTURING
Micro fractures can be derived from
both tectonic and diagenic proceses. The diagenic transformation
of Opal-A to Opal-Ct and finally to quartz creates a material
balance problem. The transition from Opal-A to Opal-Ct results
in several changes to the rock. Opal-A (SiO2*nH2O)
gives off most of its structural water resulting in an increase
of matrix density from as low as 1.8 g/cc to a range of 2.5 to
2.65 for Opal-Ct. At the same time, matrix porosity is reduced
from about 60% to about 45%. This results in a net reduction
of total rock volume (inclusive of pore space). This results
in a net expulsion of large amounts of water. As these biogenic
facies are nearly always encased in clastic- dominated clay-rich
shale sequences, complete expulsion of the water with increasing
depth of burial is not always accomplished. Thus, microscopic
discontinuities in the seemingly "welded" Opal-Ct are
held open or "wedged" by hydraulic pressure. Thus,
microfractures are created and preserved by the diagenetic phase
transformation. Most Opal-Ct intervals tend to be overpressured,
regardless of their structural setting. The trapped fluids have
preserved the micro fractures and are the cause of the overpressure.
In cleaner Opal-Ct zones, the rock
is more rigid than in the clayer intervals. Higher concentrations
of clay cause the Opal-Ct facies to deform plastically when exposed
to moderate tectonic stress. When exposed to severe tectonic
stress, the clayey Opal-Ct will exhibit both micro and macro fracturing,
but readily heals. Cleaner Opal-Ct will exhibit failure (fracturing)
at lower stress. However, even fractures in the cleaner Opal-Ct
facies will heal with time if hydraulic wedging is insufficient
to hold the fractures open.
With the transition from Opal-Ct
to quartz, there is a further decrease in rock volume due to a
reduction in porosity from 45% to less than 30% and a simultaneous
further increase in matrix density due to the final expulsion
of any residual structural water. Again, the rock must expel
water or sustain a further increas in internal pore pressure.
The net effect is that much of the micro fracturing which originated
with the first diagenic phase change and any subsequent stess
induced micro fracturing can be further preserved by the hydraulic
wedging. Again, most quartz phase biogenic shales in the subsurface
are overpressured regardless of their relationship to structure.
A.II.1.3.2 MACRO FRACTURING
Most of the natural macro fracturing
that is encountered in the diatomaceous shales is tectonically
induced. Because most of the west side major structural features
such as the Lost Hills anticline, Belridge, Pioneer, and others
are young and growing structures, any structural cause of fracturing
that is present can be thought of as an ongoing process. The
same or similar structural mechanisms govern growth of most of
the major structures paralleling the San Andreas Fault. This
type of continued deformation implies that the structure is still
growing and would favor the preservation of existing fractures
and propagation of new ones.
A.II.1.4 PRODUCTIVE POTENTIAL
OF BIOGENIC SILICEOUS SHALE RESERVOIRS
Wells drilled into a naturally fractured
biogenic siliceous shale reservoir in the quartz phase should
have about the same productive potential as such reservoirs as
the ASZ (Antelope Shale Zone) at Buena Vista Hills. Wells drilled
into biogenic siliceous shale reservoirs lacking an extensive
natural macro fracture system will have about the same productive
potential as the Cahn zone at southeast Lost Hills. Other fractured
shale analogs also exist and are further discussed in this report.
These pools, both in the San Joaquin Valley and on the coast,
have produced very large quantities of hydrocarbons at very high
rates.
A.II.1.4.1 FRACTURE STIMULATED
PRODUCTION AT LOST HILLS
There is abundant production from
diatomaceous rocks in the Lost Hills Field. In the absence of
extensive natural macro fractures, the biogenic siliceous shale
reservoirs may produce only a few barrels of oil and a few MCF
of gas per day. However, massive (250,000 to 500,000 # frac sand)
hydraulic fracture stimulation results in very high initial production
rates and cumulative production ranging from 100,000 bbl to 400,000
bbls per well. Fracture stimulated production has been obtained
from wells completed in both the Opal-Ct and quartz phase facies.
There are many high volume producing wells in the quartz-phase
Cahn Zone in the Southeast Lost Hills pool.
Opal-A reservoirs in the Etchegoin
and Reef Ridge are produced through fracture stimulation by several
operators along the anticlinal axis a few miles south of the structural
culmination. These reservoirs have moderate to high oil saturations.
Naturally fractured "Cahn chert" has been produced
for many years by Chevron through slotted liner completions in
the central portion of the field. In 1913 Chevron drilled a well
into a naturally fractured interval of the Cahn Zone. The well
produced at least into the 1950's with a gas/oil ratio of about
1500 SCF/Bbl and a water cut which increased from 50% to about
90%. Between 1949 and 1952 an additional 26 wells were put on
production.
The next significant drilling program
occurred between 1977 and 1982 when the number of Cahn completions
jumped from 36 to 259. This drilling boom was a result of what
was considered a major new pool discovery, the southeast Lost
Hills field extension. The production consists of light oil and
significant gas from somewhat naturally fractured siliceous shales
in Opal-Ct and quartz phase. Commercial production rates were
achieved by large-scale hydraulic fracture stimulation. The best
wells in this pool had IP's of as much as 600 barrels of 40-degree
oil per day, with gas and water. The completions usually consist
of a multi-stage frac over an interval of 500 to 1,000 feet.
Each frac stage is about 200 feet. The most successful frac jobs
put away over 250,000 pounds of frac sand. The pool has had a
history typical of a naturally fractured reservoir with good matrix
storage capability: the decline rates were very high initially,
but soon flattened to production of around 200 BOPD for the best
wells and 50-100 BOPD for lesser wells. After the initial decline,
most of these wells exhibit a decline rate of less than about
5%. The deepest wells on the southeast plunge are on 10 acre
spacings. Originally the reservoir was somewhat overpressured
and the IP rates declined both with the decrease in reservoir
pressure. Later wells which were drilled in marginal positions
to the main pool showed lower IP's as well.
Chevron and Mobil, as well as other
operators, are currently active in Lost Hills, at a time when
they have severely curtailed their activities in most other fields
in the San Joaquin Valley. They are clearly seeing a good return
from investment in light-oil producing Opal-Ct and quartz-phase
diatomaceous shales in central and southeast Lost Hills.
Commercial rates of production have
been obtained from wells drilled to nearly 9,000 feet in the siliceous
shales of the Southeast Lost Hills pool. These wells required
massive hydraulic fracture stimulation to achieve good results.
Most of these wells are located on the broad and less intensely
deformed southwestern flank of the southeast plunge of the structure
and do not appear to have naturally existing large scale natural
fractures. The greater success rate of the wells in this area
is due to the thicker net clean facies in the Cahn zone and the
McDonald cherts.
The most successful frac completions
tend to be in the cleanest portions of the Cahn Zone and McDonald
cherts. Wells with thicker intervals of clean diatomite tend
to produce at higher rates and have flatter declines. Several
operators are evaluating plans to drill horizontal wells in the
southeast portion of the field.
A.II.1.4.2 PRODUCTION ANALOGS
IN OTHER FIELDS
During the early 1950's the Antelope
Shale Zone Unit at Buena Vista Hills was developed on 40 acre
spacing. These wells encountered 200 feet of naturally fractured
siliceous shales at depths of 5,000 to 6,000 feet. During the
flush production of the ASZU unit, these wells produced 200 bbls
per day oil plus significant gas. During the flush production
at BVH, there were no attempts at fracture stimulation.
A.II.1.5 HIGH WATER CUTS COMMON
IN BIOGENIC SILICEOUS SHALE RESERVOIRS
The combination of the diagenic
processes and the high surface area to volume ratios associated
with the matrix porosity in any of the three diagenetic phases
results in high water cuts in most Monterey completions. Reservoirs
having light oil and higher gas oil ratios may actually have gravity
segregation as a function of pore geometry. Gas and lighter oils
may have entered pore systems having pore throats too small to
pass higher viscosity crudes. Many core descriptions refer to
dark staining (suggesting heavier oil) near fracture planes but
lighter oil and brighter fluoresence in the less fractured matrix.
Thus, it is possible that the lighter ends have penetrated into
the portion of the rock having the smaller pore throats. These
micro porous systems have higher surface to volume ratios, and
thus will have higher water saturation. When the reservoir pressure
is lowered, the gas expands and displaces significant volumes
of water from the micro pore system. It is not uncommon to have
immediate 50% water cuts in intervals far from the oil water contact.
Swn =
(Ct
*Fo - (Swb *(Ccw Cw))
* Swn-1
_________________________
Cw
Ct = 1/Rt = true formation conductivity
Cw = 1 /Rw = formation water conductivity
Ccw = clay bound water conductivity
Swb = fractional portion of total porosity saturated with clay
bound water
Deborah M. Olson William R. Berry II
California Registered Geologist #4198 California
Registered Geologist #3903